Seismic acquisition using phase-shifted sweeps

ABSTRACT

A technique includes towing at least one seismic source in connection with a survey of a structure; and operating the seismic source(s) to fire shots, where each shot is associated with a frequency sweep. The technique includes varying phases of the frequency sweeps from shot to shot according to a predetermined phase sequence to allow noise in an energy sensed by seismic sensors to be attenuated.

CROSS-REFERENCE TO RELATED APPLICATION

This application claims the benefit of U.S. Provisional PatentApplication Ser. No. 61/788,265 filed Mar. 15, 2013, which isincorporated herein by reference in its entirety.

BACKGROUND

Seismic exploration involves surveying subterranean geologicalformations for hydrocarbon deposits. A survey typically involvesdeploying seismic source(s) and seismic sensors at predeterminedlocations. The sources generate seismic waves, which propagate into thegeological formations creating pressure changes and vibrations alongtheir way. Changes in elastic properties of the geological formationscatter the seismic waves, changing their direction of propagation andother properties. Part of the energy emitted by the sources reaches theseismic sensors. Some seismic sensors are sensitive to pressure changes(hydrophones), others to particle motion (e.g., geophones), andindustrial surveys may deploy only one type of sensor, both hydrophonesand geophones, and/or other suitable sensor types. A typical measurementacquired by a sensor contains desired signal content (a measuredpressure or particle motion, for example) and an unwanted content (or“noise”).

SUMMARY

The summary is provided to introduce a selection of concepts that arefurther described below in the detailed description. This summary is notintended to identify key or essential features of the claimed subjectmatter, nor is it intended to be used as an aid in limiting the scope ofthe claimed subject matter.

In accordance with an example implementation, a technique includestowing at least one seismic source in connection with a survey of astructure; and operating the seismic source(s) to fire shots, where eachshot is associated with a frequency sweep. The technique includesvarying phases of the frequency sweeps from shot to shot according to apredetermined phase sequence to allow noise in an energy sensed byseismic sensors to be attenuated.

In accordance with another example implementation, a technique includesreceiving data acquired by sensors. The data represents energy sensed bythe sensors resulting from source energy from at least one seismicsource, which interacts with a structure. The seismic sourc-e(s) areoperated to fire shots such that each shot is associated with afrequency sweep. The technique includes varying phases of the frequencysweeps from shot to shot according to a predetermined phase sequence;and processing information derived from the data by a processor-basedmachine in an application that relies on the attenuation of noisepresent in the energy sensed by the sensors.

In accordance with another example implementation, an apparatus includesan interface to receive data acquired by sensors. The data representsenergy sensed by the sensors resulting from source energy from at leastone seismic source interacting with a structure, and the seismicsource(s) are operated to fire shots. Each shot is associated with afrequency sweep, and phases of the frequency sweeps vary from shot toshot according to a predetermined phase sequence. The apparatus includesa processor to process information derived from the data by aprocessor-based machine in an application that relies on attenuation ofnoise present in the energy sensed by the sensors.

In accordance with yet another example implementation, an articleincludes a non-transitory computer readable storage medium that storesinstructions that when executed by a computer cause the computer toreceive data acquired by sensors. The data represents energy sensed bythe sensors resulting from source energy from at least one seismicsource interacting with a structure. The seismic source(s) are operatedto fire shots, each shot is associated with a frequency sweep, and thephases of the frequency sweeps varying from shot to shot according to apredetermined phase sequence. The instructions when executed by thecomputer cause the computer to process information derived from the datain an application that relies on attenuation of noise present in theenergy sensed by the sensors.

Advantages and other features will become apparent from the followingdrawings, description and claims.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1A is a schematic diagram of a seismic acquisition system accordingto an example implementation.

FIG. 1B is an illustration of a source array used in a towed seismicsurvey according to an example implementation.

FIG. 2 is a flow diagram depicting a technique to conduct a towedseismic survey to attenuate noise according to an exampleimplementation.

FIG. 3 is a flow diagram depicting a technique to conduct a towedseismic survey to enhance source separation according to an exampleimplementation.

FIGS. 4 and 5 are flow diagrams depicting techniques to process dataacquired in a towed seismic survey according to example implementations.

FIG. 6 is a flow diagram depicting a technique to operate seismicsources in a towed seismic survey according to an exampleimplementation.

FIG. 7 is a flow diagram depicting a technique to attenuate residualshot noise according to an example implementation.

FIGS. 8 and 10 are frequency-wavenumber representations of seismic dataacquired using shots from a seismic source having the same phase.

FIGS. 9 and 11 are illustrations of frequency-wavenumber representationsof seismic data acquired using a source phase sequencing that variesfrom shot to shot according to example implementations.

FIG. 12 is a flow diagram depicting a technique to acquire and processseismic data in a manner that attenuates residual shot noise accordingto an example implementation.

FIG. 13 is a schematic diagram of a data processing system according toan example implementation.

DETAILED DESCRIPTION

Systems and techniques are disclosed herein for purposes of enhancingthe attenuation of noise from seismic data acquired in a towed survey ofa geologic structure by varying the phases of seismic source frequencysweeps. As an example, the noise may be attributable to one or moreseismic sources whose energies are being filtered out in a sourceseparation process. As another example, the noise may be residual shotnoise that is present in a given shot record and is attributable to oneor more previous shots of the same seismic source.

As a more specific example, in accordance with example implementationsthat are disclosed herein, the seismic sources are towed marine sources;and more specifically, the seismic sources may be towed marine seismicvibrators. Each vibrator is constructed to be controlled to generate asweep according to a corresponding source function (a function thatcontrols the time profile and frequency distribution of the sweep).Although the sweep may be continuous in the time domain, the sweep mayor may not contain all frequencies in the full seismic frequency range(a range between approximately 2 Hertz (Hz) to about 100 Hz). Asexamples, the sweep may contain frequencies that continuously span thefull seismic frequency range; may contain a subset of the full seismicfrequency range; or may contain discrete frequencies/frequency bands.

Although a towed marine seismic survey is described herein in exampleimplementations, it is understood that the techniques and systems thatare disclosed herein may likewise be applied to stationary marineseismic surveys (seabed or ocean bottom cable (OBC)-based surveys, forexample). Moreover, the systems and techniques that are disclosed hereinmay apply to non-seismic imaging acquisition and processing systems.Thus, many implementations are contemplated, which are within the scopeof the appended claims.

Referring to FIG. 1A, as an example of a towed survey, a marine-basedseismic data acquisition system 10 includes a survey vessel 20, whichtows one or more seismic streamers 30 (one exemplary streamer 30 beingdepicted in FIG. 1A) behind the vessel 20. It is noted that thestreamers 30 may be arranged in an array, or spread, in which multiplestreamers 30 are towed in approximately the same plane at the samedepth. As another non-limiting example, the streamers may be towed atmultiple depths, such as in an over/under spread, for example. Moreover,the streamers 30 of the spread may be towed in a coil acquisitionconfiguration and/or at varying depths or slants, depending on theparticular implementation.

A given streamer 30 may be several thousand meters long and may containvarious support cables (not shown), as well as wiring and/or circuitry(not shown) that may be used to support communication along the streamer30. In general, the streamer 30 includes a primary cable into which ismounted seismic sensors that record seismic signals. In accordance withexample implementations, the streamer 30 contains seismic sensor units58, each of which may contain a multi-component sensor. Themulti-component sensor includes a hydrophone and particle motionsensors, in accordance with some example implementations.

Thus, each sensor unit 58 may be capable of detecting a pressurewavefield and possibly, one or more component of a particle motion thatis associated with acoustic signals that are proximate to the sensor.Examples of particle motions include one or more components of aparticle displacement, one or more components (inline (x), crossline (y)and vertical (z) components (see axes 59, for example)) of a particlevelocity and one or more components of a particle acceleration.

Depending on the particular implementation, the multi-component sensormay include one or more hydrophones, geophones, particle displacementsensors, particle velocity sensors, accelerometers, pressure gradientsensors, or combinations thereof.

As a more specific example, in accordance with some implementations, aparticular multi-component sensor may include a hydrophone for measuringpressure and three orthogonally-aligned accelerometers to measure threecorresponding orthogonal components of particle velocity and/oracceleration near the sensor. It is noted that the multi-componentsensor may be implemented as a single device (as depicted in FIG. 1A) ormay be implemented as a plurality of devices, depending on theparticular implementation. A particular multi-component sensor may alsoinclude pressure gradient sensors, which constitute another type ofparticle motion sensors. Each pressure gradient sensor measures thechange in the pressure wavefield at a particular point with respect to aparticular direction.

In addition to the streamers 30 and the survey vessel 20, the seismicdata acquisition system 10 includes at least one seismic source 40, suchas the two exemplary seismic sources 40 that are depicted in FIG. 1A.More specifically, the seismic sources 40 may be seismic vibrators thatare constructed to generate energy according to sweep-based sourcefunctions, in accordance with example implementations. It is noted that,in accordance with example implementations, a group of seismic vibratorsmay form one of the sources 40 and as such, operate as a single seismicsource.

In accordance with some example implementations, the seismic sources 40may be coupled to, or towed by, the survey vessel 20. Alternatively, inother implementations, the seismic sources 40 may operate independentlyof the survey vessel 20, in that the sources 40 may be coupled to othervessels, buoys, autonomous operating vehicles, or may be in fixedpositions, as just a few examples. In yet further implementations,multiple vessels may tow the seismic sources 40.

As the seismic streamers 30 are towed, the energies produced by theseismic sources 40 generate acoustic waves 42, which are directed downthrough a water column 44 into strata 62 and 68 beneath a water bottomsurface 24. The acoustic waves 42 are reflected from the varioussubterranean geological formations, such as an exemplary formation 65that is depicted in FIG. 1A.

The incident acoustic waves 42 produce corresponding reflected acousticwaves 60, which are sensed by the seismic sensors of the streamer(s) 30.It is noted that the acoustic waves that are received and sensed by theseismic sensors include “up going” pressure waves that propagate to thesensors without reflection, as well as “down going” pressure waves thatare produced by reflections of the pressure waves 60 from an air-waterboundary, or free surface 31.

The seismic sensors of the streamers 30 generate signals (digitalsignals, for example), called “traces,” which form the acquiredmeasurements of the pressure wavefield and particle motion. The tracesare recorded as seismic data and may be at least partially processed bya signal processing unit 23 that is deployed on the survey vessel 20, inaccordance with some implementations and/or may be further processed, ingeneral, by a local or remote data processing system 620 that isgenerally depicted in FIG. 6 and described below. As an example, aparticular multi-component sensor may provide a trace, which correspondsto a measure of a pressure wavefield by its hydrophone; and the sensormay provide (depending on the particular implementation) one or moretraces that correspond to one or more components of particle motion.

A goal of the seismic acquisition may be to build up an image of asurvey area for purposes of identifying characteristics of subterraneangeological formations, such as the example geological formation 65.Subsequent analysis of the representation may reveal probable locationsof hydrocarbon deposits in subterranean geological formations. Moreover,the seismic data may be processed to determine characteristics of thegeological formation 65, such as the parameters of an elastic model,fluid properties of the formation 65 and the lithology of the formation65.

In accordance with example implementations that are disclosed herein, atechnique 200 (see FIG. 2) includes towing one or more seismic sourcesin connection with the survey of a geologic structure, pursuant to block204. The seismic source(s) may then be operated, pursuant to block 208to fire successive shots. Phases of frequency sweeps of the source(s)may then be varied (block 212) from shot to shot according to apredetermined phase sequence for purposes of attenuating noise.

For a first example implementation that is disclosed herein, the “noise”refers to energy from one or more seismic sources, which is beingfiltered out in a source separation process. Thus, the “noise” for thisexample implementation refers to the energy attributable to the seismicsource(s) other than the seismic source that is targeted as part of thesource separation. In this manner, for reasons of efficiency, multipleseismic sources may be simultaneously or near simultaneously activatedduring a towed seismic survey, and in general, source separation refersto the processing of the acquired seismic data to separate the sensedenergy according to the source. More specifically, in accordance withexample implementations that are disclosed herein, simultaneously ornear-simultaneously-activated seismic sources (vibrators, for example)generate frequency sweeps in respective shots. In other words, each shotof a seismic source is produced by varying the energy emitted by theseismic source according to an applied sweep function.

Although the sweep functions may otherwise be identical, the phaseshifts of these sweep functions are varied from shot to shot accordingto a prescribed, non-random phase sequence. In accordance with exampleimplementations, this non-random phase sequence is a sequence that wouldfail a conventional test of randomness (e.g., a pseudo-random sweepwould pass such a test) and allows the energy from two given sources tobe moved apart in some domain (the frequency-wavenumber domain, forexample). This domain separation allows separation of the sensed energyaccording to the source that produces the sensed energy, i.e., allowssource separation of the sensed energy. Moreover, as disclosed herein,the data acquired by the sensors may, depending on the particularimplementation, be in the form in which the sensed energy is alreadysource-separated or may be processed for purposes of performing sourceseparation. Thus, many implementations are contemplated, which arewithin the scope of the appended claims and described in further detailbelow.

In accordance with an example implementation, the seismic sources 40 maybe towed in generally parallel paths in a given sail direction 100, asillustrated in FIG. 1B. Moreover, as an example, some or all of theseismic sources 40 may be fired at or near the same time (i.e., therespective sweeps may begin at or near the same time) according to apath alternating sequence. As depicted in FIG. 1B, for this example, thesources 40 are arranged so that the sources 40-1 and 40-3 are inline andspaced apart by a distance called “D₁;” the sources 40-2 and 40-4 areinline in a path that is a distance called “D₂” from the inline path ofthe sources 40-1 and 40-3 and are spaced apart by the D₁ distance; andthe inline positions of the sources 40 are interleaved. As an example,the D₁ distance may be in a range of approximately five to ten meters,and the D₂ distance may be approximately 50 meters. Other D₁ and D₂distances may be used, in accordance with further implementations.

In accordance with example implementations, the seismic sources 40 areseismic vibrators, in which the phase of the energy emitted by thevibrators may be controlled in detail. In particular, the seismicvibrators are simultaneously or near-simultaneously-activated in aseries of phase shifted frequency sweeps to acquire and allow thesubsequent source separation of the acquired seismic data. In thisregard, as described above, the spacing of seismic vibrators may berelatively close.

In accordance with example implementations, the seismic vibrators areoperated pursuant to a prescribed sequence that preserves phaserelationships between the sweeps. This prescribed sequence is anon-random sequence of phases, that is, a sequence that would fail aconventional test of randomness (for example, a pseudo-random sequencewould fail such a test). The sequence is designed such that it allowsthe energy from two or more simultaneously acquired sources to be movedapart in some domain (for example, the frequency-wavenumber domain).Moreover, the source energy is acquired with relatively the same spatialsampling interval (but not with the same sample positions). Smallpositioning errors may be acceptable if used to maintain the phaserelationship from shot to shot. For example, this may be equivalent totwo experiments being acquired simultaneously, with the only differencebeing that one source has a small fixed positional shift relative to theother.

As described further below, the phase shifted sweeps may be used toseparate the acquired data from different shots in thefrequency-wavenumber (f-k) domain up to a certain frequency limit orthreshold, in accordance with example implementations. The upperfrequency threshold of this separation may depend on a number offactors, such as the number of simultaneously-activated sources and theshot sampling interval. The data acquired by the seismic sensors may beseparated using frequency-wavenumber filtering, in accordance withexample implementations. However, as further described herein, the datamay be separated using other techniques; and, in yet further exampleimplementations, explicit processing to separate the energy may not beused. For example, the non-random sequences of phase could be designedsuch that, despite the sources being acquired simultaneously, the energyfrom each source only contributes towards the desired part of theseismic image. This separation through imaging is typically referred toas “passive separation” whereas the explicit separation of sources maybe referred to as “active separation.”

As also disclosed herein, the non-random phase controlled sweeps may becombined with a higher frequency phase or time dithered signal, suchthat after signature deconvolution, the data may appear to be dithered,allowing dither-based simultaneous source separation to be applied forthose higher frequencies. For example, above the upper frequencythreshold, the sweeps may not be shifted; but rather, the sweeps may besynchronized, except for the dithering. Therefore, dither-basedsimultaneous source separation may be applied to the acquired seismicdata in this upper frequency bandwidth.

The techniques and systems that are disclosed herein may be used forpurposes of the combination of sources for over-under source sidedeghosting; increasing the sampling of the seismic wavefield on thesource side; or to acquire multiple survey lines simultaneously

Turning now to specific example implementations, two seismic sources(called “S₁” and “S₂” herein), such as seismic vibrators, may beoperated as follows. In general, the S₁ and S₂ sources may be towedbehind a vessel with a small offset (an offset of five to ten meters,for example) between the sources. For this example, the sweeps of S₁ andS₂ sources begin at the same time. However, the relative phase shiftbetween the sweeps for the S₁ and S₂ sources are varied according to adescribed, or predetermined, sequence. In this manner, each S₁, S₂source for this example emits energy due to the application of the samesweep function being applied, with the exception of a predeterminedphase shift.

For example, the S1 and S₂ sources may be fired according to thefollowing sequence:

[S ₁90+S ₂0],[S ₁0+S ₂90],[S ₁90+S ₂0],[S ₁0+S ₂90],[S ₁90+S₂0],  Firing Sequence 1

where the commas delimit each set of simultaneous shots, and the suffixproceeding the S₁/S₂ source designation denotes the relative phase indegrees. For example, for the first set of simultaneous shots by the S₁and S₂ sources in Firing Sequence 1, the S₁ source has a ninety degreephase shift with respect to the S₂ source.

To align the acquired data with the S₁ source, the resulting acquiredsensor data may be deconvolved by the following phase operator:

90,0,90,0,90,  Phase Operator 1

where the commas delimit each set of simultaneous shots. Thedeconvolution produces the following sequenced data:

[S ₁0+S ₂−90],[S ₁0+S ₂90],[S ₁0+S ₂−90],[S ₁0+S ₂90],[S ₁0+S₂−90],  Deconvolved Data Seq. 1

This deconvolved data sequence is aligned with the S1 source. To alignthe signals from the S₂ source, the acquired sensor data may bedeconvolved by the following phase operator:

0,90,0,90,0,  Phase Operator 2

This deconvolution produces the following data sequence:

[S ₁90+S ₂0],[S ₁−90+S ₂0],[S ₁90+S ₂0],[S ₁−90+S ₂0],[S ₁90+S₂0],  Deconvolved Data Seq. 2

Thus, for the Deconvolved Data Sequence 1, the phase of the S₁ source isaligned with zero degrees; and the phase of the data corresponding tothe S₂ source alternates at a 180 degree difference. The opposite istrue for the Deconvolved Data Sequence 2, in which the S₂ source data isaligned, and the S₁ source data alternates by 180 degrees. The data foreach set of two simultaneous shots may be separated after deconvolutionusing frequency-wavenumber filtering, as an example.

Thus, referring to FIG. 3, in accordance with example implementations, atechnique 300 includes towing (block 304) seismic sources in connectionwith a survey of a geologic structure. According to the technique 300,the seismic sources are operated (block 308) to fire respective shotssubstantially simultaneously/near simultaneously. The phases offrequency sweeps from shot to shot are varied (block 312) according to apredetermined phase sequence to allow energy sensed by seismic sensorsto be source separated.

Moreover, pursuant to a technique 400 of FIG. 4, on the processing side,data acquired by seismic sensors may be received (block 404) andprocessed (block 408) to perform source separation to derive sourceseparated data. This source separated data may then be processed (block412) in a seismic data processing application.

More specifically, pursuant to a technique 500 of FIG. 5, data may bereceived (block 504), which are required by seismic sensors. Pursuant tothe technique 500, the data may be deconvolved (block 508) using a phaseoperator that represents a predetermined phase sequence for purposes ofproviding deconvolved data. Frequency-wavenumber filtering may then beperformed, pursuant to block 512, of the deconvolved data for purposesof source separating the data.

As noted above, the use of the phase-shifted sweeps for sourceseparation may be applicable up to a certain frequency threshold.Therefore, referring to FIG. 6, in accordance with exampleimplementations, a technique 600 for operating a given seismic sourcemay take this into account by using prescribed phase shifting up to acertain frequency threshold and then imparting another characteristic tothe sweeps to enhance their separation from frequencies about thethreshold. The technique 600 includes applying (block 608) a prescribedphase shift and generating a sweep until a determination is made(decision block 604) that the sweep frequency is above a certainfrequency threshold. When this occurs, dithering may be applied to thesweep, pursuant to block 616 until a determination is made (decisionblock 612) that the end of the sweep has occurred (i.e., the endfrequency for the sweep has been reached).

It is noted that in accordance with further example implementations, thepredetermined phase sequences may be used for the full bandwidth, andthus, a different method may not be applied above a certain frequencythreshold.

From the data processing side, in accordance with some implementations,a frequency-diverse technique may be used to separate the data forfrequencies above the upper frequency threshold. In this manner, theadditional information that is provided across multiple frequenciesallows for separation at higher frequencies. As an example, the sweepsmay be time dithered for higher frequencies so that the resultingacquired data may be separated pursuant to a technique described in PCTPublication No. WO2013/080128 A1, entitled, “SEPARATION OF SIMULTANEOUSSOURCE DATA,” which published on Jun. 6, 2013. In this approach, timedithering is used to separate the data acquired from simultaneously ornear-simultaneously activated seismic sources. In accordance withfurther example implementations, patterns of phase shifts may bedithered, or slightly varied, for purposes of adding additionalinformation that may be used to perform source separations above theupper frequency threshold. Thus, many variations are contemplated, whichare within the scope of the appended claims.

The above-described systems and techniques may be similarly applied tomore than two sources that are operated simultaneously ornear-simultaneously. In this manner, the use of more than twosimultaneously or near-simultaneously activated sources decreases thefrequency-wavenumber separation limit and as such, the techniques maybecome more reliant on the above-described technique for separationabove the upper frequency threshold. However, low frequency data may beof more interest for certain geologic strategies, such as in some surveyareas where the target for exploration is a sub-salt or sub-basaltreservoir. Therefore, such an acquisition scheme may benefit from theuse of more than two simultaneously or near-simultaneously activatedsources.

As a more specific example, for the case of three seismic sources(called “S₁,” “S₂,” and “S₃” below), the phases of the sweep may beadjusted so that two misaligned sources have phases that alternate by120 and 240 degrees from shot to shot.

For example, the seismic sources may be fired according to the followingfiring sequence.

[S ₁0+S ₂−60+S ₃60],[S ₁180+S ₂0+S ₃0],[S ₁₀ +S ₂60+S ₃−60],[S ₁60+S₂0+S ₃120],[S ₁₀ +S ₂−180+S ₃180],[S ₁300+S ₂0+S ₃240],  Firing Seq. 3

The deconvolved data sequences are then as follows:

[S ₁0+S ₂−60+S ₃60],[S ₁0+S ₂−180+S ₃−180],[S1 0+S ₂60+S ₃−60],[S1 0+S₂−60+S ₃60],[S1 0+S ₂−180+S ₃180],[S1 0+S ₂−300+S ₃−60],  DeconvolvedData Seq. 3

[S ₁60+S ₂0+S ₃120],[S ₁180+S ₂0+S ₃0],[S ₁−60+S ₂0+S ₃−120],[S ₁60+S₂0+S ₃120],[S ₁180+S ₂0+S ₃360],[S ₁300+S ₂0+S ₃240],  Deconvolved DataSeq. 4

[S ₁−60+S ₂−120+S ₃0],[S ₁180+S ₂0+S ₃0],[S ₁60+S ₂120+S ₃0],[S ₁−60+S₂−120+S ₃0],[S ₁−180+S ₂−360+S ₃0],[S ₁60+S ₂−240+S ₃0],  DeconvolvedData Seq. 5

As can be seen from the Deconvolved Data Sequence 3, the phase of thesecond and third shots varies as −120, 240, −120, −120, −120 and −240,120, 120, 120, 240, respectively. For the deconvolved data sequence 4,the phase of the first and third shots varies as 120, −240, 120, 120,120 and −120, −120, 240, 240, −120, respectively. For the DeconvolvedData Sequence 5, the phase of the first and second shots varies as 240,−120, −120, −120, 240 and 120, 120, −240, −240, 120, respectively.

If it is noted that a phase shift of −120 is equivalent to one of 240,and a phase shift of −240 is equivalent to one of 120, then it may berecognized that the Firing Sequence 3 has the desired properties.

It is noted that explicit source separation may not be performed inaccordance with example implementations. In this manner, in accordancewith some example implementations, the acquired data may be processed toperform deghosting and/or imaging applications without explicitlyseparating the simultaneous sources. In this case, the non-random phasesequence may be designed such that the simultaneous sources onlycontribute to the part of the image that they were intended to.

For other applications, particularly in the case of over-under sources,the wavefields may be combined prior to source separation and sourceseparation may be performed afterwards. For example, a technique such asthe one described in PARKES, G., AND HEGNA, S., 2011, “AN ACQUISITIONSYSTEM THAT EXTRACTS THE EARTH RESPONSE FROM SEISMIC DATA, FIRST BREAK,VOL. 29, No. 12, pp. 81-87 may be used, where over-under sources arecombined for deghosting prior to separation of the data (in thisspecific case, the deghosting operation itself separates the data).

In accordance with further example implementations, a predeterminedphase sequence may be used to attenuate residual shot noise from one ormore previous shots of the same seismic source. In particular, arelatively simple repeating pattern of phase shifts may be used thatcauses a residual shot noise to be heterodyned, or aliased, away fromthe signal in the frequency-wavenumber domain of a common receivergather. In this manner, in the towed survey, the shots from a givenseismic source are fired “on time,” rather than “on position.”Therefore, there is a relatively rigid timing synchronization betweenthe shots of the given seismic source so that the phase relationshipsbetween the shots are not disturbed.

The techniques and systems that are disclosed herein may be used toallow the residual shot noise to be removed by applyingfrequency-wavenumber filtering (or other techniques) and does not relyon sacrificing spatial resolution. Moreover, as a result of thereduction of the residual shot noise, the typical length of time betweensuccessive shots may be shortened. In traditional seismic sourcecontrol, the time between successive shots may be selected to be largerthan desirable so the residual shot noise decays to a sufficiently smalllevel in the current shot record. The techniques and systems that aredisclosed herein, therefore, may reduce this time between successiveshots.

More specifically, residual shot noise originates from a given seismicsource that was used in a previous shot or shots. The shot intervaltypically is much longer than the two-way-time (TWT) to the imagingtarget for purposes of allowing the residual shot noise to decay to anacceptable level before the next shot is fired. Waiting for the residualshot noise to decay, however, may introduce several challenges. Forexample, the spatial shot interval may be inadequate (too large), andthe vessel speed towing the seismic spread may be too slow. If a time isnot used for the residual shot noise to decay before firing the nextshot, a closer shot spacing may be used, leading to relatively improvedseismic imaging. Alternatively, the shot spacing may be maintained whilethe vessel speed is increased, thereby leading to greater efficiency inthe seismic acquisition.

Thus, referring to FIG. 7, in accordance with example implementations, atechnique 700 includes towing (block 704) a seismic source in connectionwith the survey of a geologic structure and operating (block 708) theseismic source to fire successive shots. Phases of frequency sweeps arevaried (block 712) from shot to shot according to a predetermined phasesequence to attenuate residual shot noise from one or more previousshots.

It is possible to use the same source signature for each shot, inaccordance with example implementations. In general, the residual shotnoise lies in the same place as the signal in the frequency-wavenumbercommon receiver domain, and the residual shot noise typically has alower amplitude than the seismic signal and is predominantly lowfrequency. Because the residual shot noise and the seismic signal occupythe same frequency-wavenumber space, it may be challenging to separatethe signal from the residual shot noise. More specifically, FIG. 8depicts an illustration 800 of acquired energy in thefrequency-wavenumber domain when the same phase is used from shot toshot. As depicted in FIG. 8, for a given signal cone 802, signal energy804 generally is present in the same frequency-wavenumber space asresidual shot noise 806, i.e., shot noise from the previous shot forthis example. Due to the co-location of the residual shot noise energy806 and signal energy 804, it may be particularly challenging toseparate the signal energy 804 from the residual shot noise 806.

In accordance with example implementations, the seismic source is firedaccording to a predetermined phase sequence for purposes of separatingresidual shot noise energy from the signal energy. If a positive 90degree phase shift is applied to the source signal of alternative shotsfrom the same seismic source, the shots from the source may berepresented in phases as follows:

+90,0,+90,0,+90,0  Firing Seq. 4.

The residual shot noise, with this sequence, has the phase from theprevious shot and has corresponding phases from the following shots, asdescribed below:

0,+90,0,+90,0,+90  Residual Shot Noise Seq. 1.

Each shot (and the residual shot noise from the previous shot) may thenbe deconvolved using the shot's phase. The applied deconvolutionoperator has phases, which are the inverse of the signal phases, asrepresented below:

−90,0,−90,0  Deconvolution Operator Phases 1.

After deconvolution, the signal, as expected, has zero phase shift forall shots, as represented below:

0,0,0,0,0,0,0  Deconvolved Data Seq. 6.

But after deconvolution, the residual shot noise has alternate negativeand positive 90 degree phases, as represented below:

−90,+90,−90,+90,−90,+90  Residual Shot Noise Seq. 2.

This means that the residual shot noise in each deconvolved shot isphase-reversed relative to the residual shot noise in the previousdeconvolved shot. The deconvolved shots have the signal, which issubstantially the same from one shot to the next, but with the residualshot noise being reversed in phase between one shot and the next.Because of the successive phase reversion, the residual shot noise isheterodyned, or aliased, as depicted in an illustration 900 of FIG. 9.In this manner, referring to FIG. 9, for this example, the signal energy804, remains inside a signal cone, such as example signal cone 802, withthe residual shot noise energy 806 being generally aliased outside ofthe signal cone 802. This permits, for example, frequency-wavenumberfiltering to be applied to remove a significant portion, if not all, ofthe residual shot noise energy 806.

In accordance with further example implementations, the residual shotnoise may be removed from the shot before the previous one or, ingeneral, placed in a more optimal position than halfway between thesignal cones. For this purpose, a different pattern of phase shifts maybe employed. More specifically, as depicted in an illustration 1000 ofFIG. 10, the residual shot noise from one shot before (herein called the“RSN2” residual shot noise energy 1010) may be aliased back into thesignal cone 802, along with the residual shot noise energy from theimmediately preceding shot (herein called the “RSN1” residual shot noiseenergy 806), if the phases of the shots are not varied. To remove boththe RSN1 806 and RSN2 1010 residual shot noise energies, the relativephase shift of the RSN1 residual shot noise energy 806 is set to be 120degrees, instead of 180 degrees. The shift of RSN2 residual shot noiseenergy 1010 is then set to be 240 degrees, to heterodyne the RSN1 andRSN2 shot noise energies, as depicted in FIG. 11. In this regard,referring to FIG. 11, an illustration 1100 of the frequency-wavenumberspace, the above-described heterodyning moves RSN1 806 and RSN2 1010residual shot noise energies generally outside of the signal cone 802.This allows the application of frequency-wavenumber filtering forpurposes of significantly attenuating both the RSN1 and RSN2 residualshot noises.

In general, it is beneficial if the residual shot noise of the previousshot has a phase shift of θ relative to the previous shot. To accomplishthis, the sequence of source phases (called “Ø(n)” may be used, asdescribed by the follow function:

Ø(n)=2.Ø(n−1)−Ø(n−2)−θ,  Eq. 1.

where “n” is the shot index; and θ” represents a pre-selected constant,or fixed value.

For the example above, θ is set equal to 180 degrees, and the sequencemay be described as follows:

TABLE 1 RSN1 DECONVOLVED SOURCE PHASE (ø),, PHASE DIFFERENCE (Θ) 0 90270 0 90 180 90 270 180 0 90 180 90 270 180 0 90 180 90 270 180 0 90 18090 270 180 0 90 180 90 270 180 0 90 180 90 270 180 0 90 180 90 270 180 090 180 90 270 180 0 90 180 90 270 180

If a 120 degree shift in the residual shot noise phase is desired ateach shot, then the following sequence may be used.

TABLE 2 RSN1 DECONVOLVED SOURCE PHASE (ø),, PHASE DIFFERENCE (Θ) 0 60300 0 60 120 180 180 120 240 300 120 180 60 120 0 180 120 60 300 120 060 120 180 180 120 240 300 120 180 60 120 0 180 120 60 180 120 60 300120 0 60 120 180 180 120 240 300 120 180 60 120 0 180 120 60 300 120

Other phase shifts may be applied to the residual shot noise, inaccordance with further implementations.

Thus, referring to FIG. 12, in accordance with example implementations,a technique 1200 includes towing (block 1204) a seismic source inconnection with a survey of a geologic structure and operating (block1208) the seismic source to fire successive shots. The technique 1200includes varying the phases of frequency sweeps from shot to shotaccording to a predetermined phase sequence based at least in part on apredetermined residual shot noise shift per shot, pursuant to block1212. Pursuant to block 1216, the acquired seismic data may then beprocessed to deconvolve the data using a deconvolution operator having aphase sequence based at least in part on the shot phase sequence.

The above discussion assumes that the vibrator may be controlled to emita sweep with a defined phase shift φ. The frequency sweep may becontrolled via a pilot sweep (called “S(t)”), which may, in accordancewith example implementaitons, be represented as follows:

S(t)=sin [2π∫₀ ^(t) f(t′)dt′].  Eq. 2

To generate a pilot sweep S(t) with a phase shift φ, the pilot sweepS(t) may be represented as follows:

S(t)=sin [φ+2π∫₀ ^(t) f(t′)dt′].  Eq. 3

For the example implementation discussed above in which the phase shiftφ alternates between 0 and 90 degrees, the sweeps may alternate betweensine and cosine sweeps of the same function, as described below:

S _(odd)(t)=sin [2π∫₀ ^(t) f(t′)dt′],  and Eq. 4

S _(even)(t)=cos [2π∫₀ ^(t) f(t′)dt′].  Eq. 5

Referring to FIG. 13, in accordance with some implementations, a dataprocessing system 1320 (a computer, for example), may contain aprocessor 1350 for purposes of processing the acquired seismic data. Thedata processing system 1320 is an actual machine made from actualhardware and actual machine executable instructions (or “software”). Inaccordance with example implementations, the processor 1350 may beformed from one or more microprocessors and/or microprocessor processingcores. In general, the processor 1350 is a general purpose processor,and may be formed from, depending on the particular implementation, oneor multiple central processing units (CPUs), or application specificintegrated circuits (ASICs), field programmable gate arrays (FPGAs),programmable logic devices (PLDs), or other appropriate devices, as canbe appreciated by the skilled artisan. As a non-limiting example, theprocessor 1350 may be part of the circuitry 23 (see FIG. 1A) on thevessel 20, or may be disposed at a remote site. Moreover, the dataprocessing system 1320 may be a distributed processing system, inaccordance with further implementations.

As depicted in FIG. 13, the processor 1350 may be coupled to acommunication interface 1360 for purposes of receiving data 1322, whichrepresents data acquired by seismic sensors and generally representsdata resulting from the interaction of source energy with a geologicstructure, where the source energy is the result of the application ofthe phase-shifted sweep functions, as described herein. As examples, thecommunication interface 1360 may be a Universal Serial Bus (USB)interface, a network interface, a removable media interface (a flashcard, CD-ROM interface, etc.) or a magnetic storage interface (anIntelligent Device Electronics (IDE)-compliant interface or SmallComputer System Interface (SCSI)-compliant interface, as non-limitingexamples). Thus, the communication interface 1360 may take on numerousforms, depending on the particular implementation.

In accordance with some implementations, the processor 1350 is coupledto a memory 1340 that stores program instructions 1344, which whenexecuted by the processor 1350, may cause the processor 1350 to performvarious tasks of one or more of the techniques that are disclosedherein, such as the techniques 200, 300, 400, 500, 600, 700 and/or 1200,as examples.

As a non-limiting example, in accordance with some implementations, theinstructions 1344, when executed by the processor 1350, may cause theprocessor 1350 to process information derived from the data received bythe interface 1360 in an application (an image construction applicationor a deghosting application, as examples), which relies on attenuationof noise present in the energy sensed by the sensors.

In general, the memory 1340 is a non-transitory storage medium and maytake on numerous forms, such as (as non-limiting examples) semiconductorstorage, magnetic storage, optical storage, phase change memory storage,capacitor-based storage, and so forth, depending on the particularimplementation. Moreover, the memory 1340 may be formed from more thanone of these non-transitory storage mediums, in accordance with furtherimplementations. When executing one or more of the program instructions1344, the processor 1350 may store preliminary, intermediate and/orfinal results obtained via the execution of the instructions 1344 asdata 1348 that may be stored in the memory 1340.

It is noted that the data processing system 1320 is merely an example ofone out of many possible architectures, in accordance with thetechniques and systems that are disclosed herein. Moreover, the dataprocessing system 1320 is represented in a simplified form, as theprocessing system 1320 may have various other components (a display todisplay initial, intermediate and/or final results of the system'sprocessing, as non-limiting examples), as can be appreciated by theskilled artisan.

Other variations are contemplated, which are within the scope of theappended claims. For example, the systems and techniques that aredisclosed herein may be applied to energy measurement acquisitionssystems, other than seismic acquisition systems. For example, thetechniques and systems that are disclosed herein may be applied tonon-seismic-based geophysical survey systems, as electromagnetic ormagnetotelluric-based acquisition systems, in accordance with furtherimplementations. The techniques and systems that are disclosed hereinmay also be applied to energy measurement acquisition systems, otherthan systems that are used to explore geologic regions. Thus, althoughthe surveyed target structure of interest described herein is a geologicstructure, the target structure may be a non-geologic structure (humantissue, a surface structure, and so forth), in accordance with furtherimplementations.

While a limited number of examples have been disclosed herein, thoseskilled in the art, having the benefit of this disclosure, willappreciate numerous modifications and variations therefrom. It isintended that the appended claims cover all such modifications andvariations.

What is claimed is:
 1. A method comprising: towing at least one seismicsource in connection with a survey of a geologic structure; operatingthe at least one seismic source to fire shots, each shot beingassociated with a frequency sweep; and varying phases of the frequencysweeps from shot to shot according to a predetermined phase sequence toallow noise in an energy sensed by seismic sensors to be attenuated. 2.The method of claim 1, wherein: the at least one seismic sourcecomprises a plurality of seismic sources; operating the seismic sourcescomprises operating the seismic sources to fire respective shots atsubstantially the same time; and varying the phases allows the energysensed by the seismic sensors to be source separated.
 3. The method ofclaim 2, wherein varying the phases comprises varying phases of theassociated frequency sweep from shot to shot for each of the seismicsources.
 4. The method of claim 2, wherein operating the plurality ofseismic sources comprises operating a plurality of seismic vibrators. 5.The method of claim 2, wherein varying the phases comprises varying thephases to allow the energy to be separated up to a predefined frequencythreshold.
 6. The method of claim 1, wherein: operating the at least oneseismic source comprises operating a given seismic source to firesuccessive shots, each of the successive shots being associated with oneof the frequency sweeps; and varying the phases comprises varying thephases of the frequency sweeps associated with the successive shots toallow residual shot noise associated with the given seismic source to beattenuated.
 7. The method of claim 6, wherein varying the phases of thefrequency sweeps associated with the successive shots comprises varyingthe phases based at least in part on a predetermined residual shot noiseshift per shot.
 8. The method of claim 6, wherein varying the phases ofthe frequency sweeps associated with the successive shots comprisevarying the phases according to a function Ø(n)=2·Ø(n−1)−Ø(n−2)−θ, whereØ(n) represents a phase of shot n and θ is a fixed phase shift.
 9. Themethod of claim 8, wherein θ is near or at 180 degrees.
 10. The methodof claim 6, wherein varying the phases of the frequency sweeps compriseregulating the sweeps such that the sweeps alternate between a sine anda cosine of a given phase function.
 11. The method of claim 1, whereinvarying the phases comprises varying the phases according to a repeatingpattern.
 12. A method comprising: receiving data acquired by sensors,the data being representing energy sensed by the sensors resulting fromsource energy from at least one seismic source interacting with astructure, wherein the at least one seismic source is operated to fireshots, each shot being associated with a frequency sweep, and phases ofthe frequency sweeps varying from shot to shot according to apredetermined phase sequence; and processing information derived fromthe data by a processor-based machine in an application that relies onattenuation of noise present in the energy sensed by the sensors. 13.The method of claim 12, wherein: the at least one seismic sourcecomprises a plurality of seismic sources; the plurality of seismicsources are operated to fire respective shots at substantially the sametime; and processing the information comprises processing theinformation in an application that relies on source separation.
 14. Themethod of claim 13, further comprising: performing frequency-wavenumberfiltering of the data to generate the information derived from the data.15. The method of claim 13, wherein the processing comprises: processingthe first data in the application without first processing the firstdata to perform active source separation.
 16. The method of claim 13,wherein the processing comprises: performing deghosting or constructingan image based on the first data.
 17. The method of claim 12, wherein:the at least one seismic source comprises a given seismic sourceoperated to first successive shots, each of the successive shots beingassociated with one of the frequency sweeps; and processing theinformation comprises processing the information in an application thatrelies on attenuation of residual shot noise.
 18. An apparatuscomprising: an interface to receive data acquired by sensors, the databeing representing energy sensed by the sensors resulting from sourceenergy from at least one seismic source interacting with a structure,wherein the at least one seismic source is operated to fire shots, eachshot being associated with a frequency sweep, and phases of thefrequency sweeps varying from shot to shot according to a predeterminedphase sequence; and a processor to process information derived from thedata by a processor-based machine in an application that relies onattenuation of noise present in the energy sensed by the sensors. 19.The apparatus of claim 18, wherein: the at least one seismic sourcecomprises a plurality of seismic sources; the plurality of seismicsources are operated to fire respective shots at substantially the sametime; and the processor is adapted to process the information in anapplication that relies on source separation.
 20. The apparatus of claim18, wherein: the at least one seismic source comprises a given seismicsource operated to first successive shots, each of the successive shotsbeing associated with one of the frequency sweeps; and the processor isadapted to process the information in an application that relies onattenuation of residual shot noise.
 21. An article comprising anon-transitory computer readable storage medium storing instructionsthat when executed by a computer cause the computer to: receive dataacquired by sensors, the data being representing energy sensed by thesensors resulting from source energy from at least one seismic sourceinteracting with a structure, wherein the at least one seismic source isoperated to fire shots, each shot being associated with a frequencysweep, and phases of the frequency sweeps varying from shot to shotaccording to a predetermined phase sequence; and process informationderived from the data in an application that relies on attenuation ofnoise present in the energy sensed by the sensors.